Crude oils, their straight-run and cracked fractions and other petroleum products contain sulphur in varying amounts, depending upon the source of the crude oil and any subsequent treatment that it may have undergone. Besides elemental sulphur, numerous sulphur compounds have been identified in crude oil including hydrogen sulphide (H.sub.2 S), C.sub.1 to C.sub.5 primary alkyl mercaptans, C.sub.3 to C.sub.8 secondary alkyl mercaptans, C.sub.4 to C.sub.6 tertiary alkyl mercaptans, cyclic mercaptans (such as cyclopentane thiol, cyclohexane thiol and cis-2-methylcyclopentane thiol), open chain sulphides of the formula R--S--R' where R and R' represent C.sub.1 to C.sub.4 alkyl groups, mono-, bi- and tri-cyclic sulphides, thiophene, alkyl substituted thiophenes, condensed thiophenes (such as benzo(b)thiophene, isothionaphthene, dibenzothiophene, and benzo(b)naphtho(2,1-d)thiophene), thienothiophenes, alkyl cycloalkyl sulphides, alkyl aryl sulphides, 1-thiaindans, aromatic thiols (such as thiophenol), and cyclic thiols such as cyclohexane thiol.
Most of the sulphur compounds that have been positively identified as components of crude oil boil below about 200.degree. C. Many other sulphur compounds of high molecular weight and high boiling point remain unidentified in crude oil.
For a variety of reasons it is necessary to treat crude oil and petroleum fractions derived therefrom to reduce or remove the sulphur components present therein. Otherwise subsequent processing may be hindered, for example because the sulphur components may adversely affect the performance of a catalyst. If the hydrocarbon fraction is intended for fuel use, then burning of the fuel will result in any sulphur components present therein being converted to sulphur oxides which are environmentally damaging. Moreover the level of particulates in the combustion products of liquid fuels is linked to the sulphur content of the fuel.
For these reasons it is necessary to remove as far as possible the sulphur content from hydrocarbon fractions derived from crude oil, such as gasoline fractions, diesel fuel, gas oils and the like. Typically such sulphur removal is carried out by a process known generally as hydrodesulphurisation. In such a process the hydrocarbon fraction is admixed with hydrogen and passed over a hydrodesulphurisation catalyst under appropriate temperature and pressure conditions. In such a process the aim is to If rupture the carbon-sulphur bonds present in the feedstock and to saturate with hydrogen the resulting free valencies or olefinic double bonds formed in such a cleavage step. In this process the aim is to convert as much as possible of the organic sulphur content to hydrocarbons and to H.sub.2 S.
Generally the cyclic sulphur-containing compounds are harder to hydrogenate than the open chain compounds and, within the class of cyclic sulphur-containing compounds, the greater the number of rings that are present the greater is the difficulty in cleaving the carbon-sulphur bonds. The presence of alkyl or other substituent groups on the basic ring system can further reduce the reactivity of the organic sulphur compounds towards hydrodesulphurisation.
The specification for Swedish Class I diesel fuel, which is required for use in urban areas, stipulates a maximum aromatics content of 5 volume % and a maximum sulphur content of 10 ppm, while the corresponding specification for Class II diesel fuel limits the aromatics to 20 volume % and sulphur to a maximum of 50 ppm; Class III diesel fuel has a 25 volume % limit on aromatics and a maximum of 500 ppm of sulphur.
When a hydrocarbon feedstock is treated with hydrogen in the presence of a suitable catalyst with the aim of effecting hydrodesulphurisation, other reactions may also occur. Hence hydrotreatment is often used as a more general term to embrace not only the hydrodesulphurisation reactions but also the other reactions including hydrocracking, hydrogenation and other hydrogenolysis reactions, such as hydrodenitrogenation (HDN), hydrodeoxygenation (HDO), and hydrodemetallation (HDM).
There are four main hydrogenolysis reactions, hydrodesulphurisation (HDS), hydrodenitrogenation (HDN), hydrodeoxygenation (HDO), and hydrodemetallation (HDM). Amongst catalysts which have been proposed for such hydrotreating reactions are molybdenum disulphide, tungsten sulphide, sulphided nickel-molybdate catalysts (NiMoS.sub.x), and cobalt-molybdenum sulphide supported on alumina (Co--Mo/alumina).
It was generally considered that the simultaneous occurrence of some hydrogenation reactions, such as the facile hydrogenation of olefins and the more difficult hydrogenation of aromatic hydrocarbons, was not advantageous in a hydrotreatment process because the use of valuable hydrogen beyond the point at which the product meets the required specification incurs unnecessary cost. However, the present and future specifications for liquid fuel products will require that future processes will have to provide, amongst other things, liquid fuels and refinery intermediate streams containing substantially lower organic sulphur, organic nitrogen and aromatics contents than have been acceptable in the past. Therefore processes which facilitate these further hydrogenation reactions are becoming increasingly important.
There is a historical trend towards the use of heavier crude oils in refining. Hence the production of higher quality products and refinery intermediate streams from less suitable raw materials requires improved processes. These include residue hydrocracking and catalytic cracking to effect a reduction in the molecular weight of the feed, as well as hydrotreating in order to remove organic sulphur and nitrogen compounds, along with hydrogenation to reduce the aromatics content. Hence, under current conditions and increasingly for the future, it will be desirable to combine hydrodesulphurisation and hydrodenitrogenation with aromatic hydrogenation in advanced hydrotreating processes.
In contrast, except when processing high molecular weight residues, extensive hydrocracking reactions are to be avoided in most refinery hydrotreating operations as far as possible because they are highly exothermic and can cause thermal damage to catalysts and reaction vessels, as well as leading to the deposition of carbonaceous materials causing :,loss of catalyst activity. Thus an operator of a hydrodesulphurisation plant has reported in an article "Refiners seek improved hydrogen production", Oil & Gas Journal, Jul. 20, 1987, pages 48 and 49, that reactors in service have overheated severely, one to the point of rupture, due to unwanted hydrocracking reactions occurring.
The danger of such hydrocracking reactions occurring can be minimised by ensuring that the catalyst remains adequately sulphided during use.
A number of papers have appeared in the literature relating to hydrodesulphurisation technology, including:
(a) "Kinetics of Thiophene Hydrogenolysis on a Cobalt Molybdate Catalyst", by Charles N. Satterfield et al, AIChE Journal, Vol. 14, No. 1 (January 1968), pages 159 to 164; PA0 (b) "Hydrogenation of Aromatic Hydrocarbons Catalysed by Sulfided CoO--MoO.sub.3 /gamma-Al.sub.2 O.sub.3. Reactivities and Reaction Networks" by Ajit V. Sapre et al, Ind. Eng. Chem. Process Des. Dev, Vol. 20, No. 1, 1981, pages 68 to 73; PA0 (c) "Hydrogenation of Biphenyl Catalyzed by Sulfided CoO--MoO.sub.3 /gamma-Al.sub.2 O.sub.3. The Reaction Kinetics", by Ajit V. Sapre et al, Ind. Eng. Chem. Process Des. Dev, Vol. 21, No. 1, 1982, pages 86 to 94; PA0 (d) "Hydrogenolysis and Hydrogenation of Dibenzothiophene Catalyzed by Sulfided CoO--MoO.sub.3 /gamma-Al.sub.2 O.sub.3 : The Reaction Kinetics" by D. H. Broderick et al, AIChE Journal, Vol. 27, No. 4, July 1981, pages 663 to 672; and PA0 (e) "Hydrogenation of Aromatic Compounds Catalyzed by Sulfided CoO--MoO.sub.3 /gamma-Al.sub.2 O.sub.3 " by D. H. Broderick et al, Journal of Catalysis, Vol. 73, 1982, pages 45 to 49.
A review of the reactivity of hydrogen in sulphided catalysts, such as those used as hydrotreating catalysts, appears on pages 584 to 607 of the book "Hydrogen Effects of Catalysis" by Richard B. Moyes, published by Marcel Dekker, Inc. (1988).
A review of industrially practised hydrotreating processes is published each year in the Journal "Hydrocarbon Processing". For example reference may be made to "Hydrocarbon Processing", November 1990, page 112 et seq and to "Hydrocarbon Processing", November 1992, page 178 et seq.
An outline of three prior art hydrotreating processes appears in "Hydrocarbon Processing 1988 Refining Handbook" on pages 78 and 79 of "Hydrocarbon Processing", September 1988. In the "Chevron RDS/VRDS Hydrotreating Process" a mixture of fresh liquid hydrocarbon feedstock, make-up hydrogen and recycled hydrogen is fed to a reactor in a "once-through" operation for the liquid feed. As illustrated the reactor has three beds and inter-bed cooling is provided by injection of further amounts of recycle hydrogen. The recycle hydrogen is passed through an H.sub.2 S scrubber. In the "HYVAHL Process" a once-through operation for the liquid feed is also used. Again, amine scrubbing is used to remove H.sub.2 S from the recycle hydrogen. The "Unionfining Process" also utilises a once-through basis for the liquid feed. Co-current hydrogen and liquid flow is envisaged. Unreacted hydrogen is partially recycled.
In all three processes gas recycle is used to cool the catalyst bed and so minimise the risk of thermal runaways occurring as a result of significant amounts of hydrocracking taking place. Use of gas recycle means that inert gases, that is to say gases other than hydrogen, tend to accumulate in the circulating gas which in turn means that, in order to maintain the desired hydrogen partial pressure, the overall operating pressure must be raised to accommodate the circulating inert gases and that the size and cost of the gas recycle compressor must be increased and increased operating costs must be tolerated.
In an article entitled "Reduction of aromatics in diesel" which appeared in "Hydrocarbon Technology International 1994", edited by Peter Harrison, published by Sterling Publications Limited, B. H. Cooper et al describe a dual-stage process developed by Haldor Tops.phi.e for low-aromatics diesel production which involves initial hydrotreating using a high activity base-metal catalyst, such as a high activity NiMo catalyst, intermediate stripping of the cold hydrotreated intermediate product to remove H.sub.2 S and NH.sub.3, followed by a second stage of aromatics hydrogenation using a sulphur-tolerant noble-metal catalyst, and product stripping. Further information concerning this process are to be found in an article entitled "Diesel aromatics saturation, a comparative study of four catalyst systems" by B. P. Cooper et al, ACS Preprints, Div. of Fuel Chemistry, Vol. 37, No. 1, 1992, pages 41 to 49, and in a paper presented to the National Petroleum Refiners Association at the 1992 NPRA Annual Meeting, Mar. 22-24, 1992, Marriott/Sheraton, New Orleans, La., U.S.A. with the title "Tops.phi.e's process for improving diesel quality", AM-92-50, by Peter S.phi.gaard-Andersen et al.
Hydrorefining of a naphtha feedstock is described in U.S. Pat. No. 4,243,519. This appears to involve a substantially wholly vapour phase process using two hydrorefining stages. A sulphur-containing naphtha feedstock is mixed with the gas from the second hydrorefining stage and passed to the first hydrorefining stage. The first hydrorefining stage is followed by a separation stage in which a gaseous phase containing a major portion of the hydrogen sulphide formed in the first hydrorefining stage is separated from a partially desulphurised naphtha which is mixed with fresh hydrogen before passing to the second hydrorefining stage.
Multiple stage hydrodesulphurisation of residuum with movement of catalyst between stages in the opposite direction to movement of gas and liquid is described in U.S. Pat. No. 3,809,644.
U.S. Pat. No. 3,847,799 describes conversion of black oil to low-sulphur fuel oil in two reactors. Make-up hydrogen is supplied to the second reactor but in admixture with hydrogen exiting the first reactor that has been purified by removal of hydrogen sulphide therefrom. Hence hydrogen is recovered from the first reactor and recycled to the second reactor in admixture with inert gases which will accordingly tend to accumulate in the gas recycle loop. Any condensate obtained from the first reactor is admixed with product from the second reactor.
Hydrorefining of a heavy hydrocarbonaceous oil containing certain types of sulphur compounds such as dibenzothiophenes, in two stages with interstage removal of hydrogen sulphide and ammonia is described in U.S. Pat. No. 4,392,945. A nickel catalyst is used in the first stage and a cobalt catalyst in the second stage. A further example of a multistage hydrodesulphurisation process in which hydrogen sulphide and ammonia are removed between stages is described in U.S. Pat. No. 3,717,571.
In U.S. Pat. No. 4,048,060 there is disclosed a two-stage hydrodesulphurisation process with optional removal of hydrogen sulphide from the hydrotreated product between stages. This proposal utilises a first stage catalyst and a second stage catalyst which comprise Group VIB and Group VIII metal components. The second stage catalyst has a narrow and critical range of pore size distribution and relatively larger pores than the first stage catalyst. The hydrogen-containing treating gas is recycled to the hydrotreating zones, usually after removal of hydrogen sulphide.
U.S. Pat. No. 4,051,020 describes countercurrent passage of a hydrocarbon oil to be desulphurised and hydrogen through a reaction vessel with catalyst particles moving from stage to stage in the reactor concurrently with either the liquid phase or the gas phase.
In FR-A-2014517 a sulphur-containing oil is mixed with a hydrogen-rich gas, heated in a furnace and then passed upwardly through a reactor containing a catalyst supported on a grill.
U.S. Pat. No. 3,425,810 illustrates a multi-tray hydrotreating apparatus with provision for counter-current flow of oil and hydrogen.
In U.S. Pat. No. 3,519,557 there is taught a process for hydrogenating hydrocarbon feedstocks using three reactors in series, with flash towers following each stage, the flashed liquid stream from the first reactor forming the feed stream to the second reactor, and that from the second reactor forming the feed to the third reactor. According to this proposal the first reactor is fed with fresh make-up gas and the second and third reactors with a mixture of fresh make-up gas and recycle high purity hydrogen. Flashing is effected by suddenly reducing the pressure in each flash tower. According to column 4 lines 7 to 11 liquids from Stage 2 are charged with make-up hydrogen to Stage 3; however, according to column 4 lines 16 to 18 hydrogen from flashing tower 3 and from the hydrogen scrubber 4 are returned to reactors 2 and 3 by means of compressor 6. No provision is made for controlling the level of inert gases in the recycle hydrogen; presumably such inert gases leave the plant dissolved in the product from product fractionator 5.
U.S. Pat. No. 3,900,390 discloses hydroprocessing of hydrocarbon charges in two moving bed reactors, the first of which is fed with a mixture of feedstock and recycle hydrogen. The catalyst-containing mixture emerging from the bottom of the first reactor passes to a separator from which the gas phase and light hydrocarbons are taken to a condenser. The light hydrocarbons are recovered while the gas phase is scrubbed with an amine and admixed with fresh hydrogen for admission to the second moving bed reactor along with the liquid phase and catalyst from the separator.
A hydrofining-reforming process in which a sulphur-containing hydrocarbon feedstock is given a two stage hydrofining treatment is described in U.S. Pat. No. 3,884,797. A feed naphtha is mixed with recycle and make-up hydrogen and fed to the first hydrofining reactor. The effluent is cooled and washed with water to remove ammonia and a substantial proportion of the hydrogen sulphide. After separation from the gas stream the condensate is then flashed into a low pressure separator from which a mixture of C.sub.1 to C.sub.3 hydrocarbons is recovered. The flashed condensate is then stripped with make-up hydrogen, the stripping gas being passed to the first hydrofining reactor. The stripped condensate passes on to a hydrosorbing stage and then to catalytic reforming.
A hydrocracking process with pre-hydrofining that uses a gas oil feedstock is described in U.S. Pat. No. 3,364,133. The flow sheet for this process is somewhat similar to that of U.S. Pat. No. 3,884,797.
Another plant with a somewhat similar flow sheet for converting hydrocarbonaceous black oils into lower boiling hydrocarbons using hydrodesulphurisation catalysts is described in U.S. Pat. No. 4,159,935.
WO-A-92/16601 describes a process for producing diesel fuel from a diesel hydrocarbon feed which is fed concurrently with hydrogen to a first hydrogenation zone from which there is recovered a liquid effluent. That liquid effluent is then passed to a second hydrogenation zone in which it is contacted countercurrently with hydrogen. A similar proposal appears in FR-A-2151059.
In U.S. Pat. No. 2,952,626 it is proposed to hydrofine a gas oil feed in a first stage under mixed vapour and liquid phase conditions, using co-current flow with a mixture of recycle gas and make-up hydrogen, and then to subject the liquid phase in countercurrent flow with hydrogen in a second stage.
GB-A-901332 proposes using two stage catalytic pressure refining of hydrocarbon fractions wherein a refining gas which contains less than 60 a by volume of hydrogen, such as a coke oven gas, is used in the first stage while practically pure hydrogen is used in the second stage. The Examples describe treatment of a light oil obtained by gasification of crude petroleum and treatment of a crude benzene.
A multi-stage hydrodesulphurisation process using unusually high space velocities and inter-stage removal of H.sub.2 S is described in U.S. Pat. No. 3,349,027.
U.S. Pat. No. 4,016,069 teaches a multiple stage process for hydrodesulphurising a residual oil comprising passing the oil downwardly through a plurality of stages in series with an interstage flashing step. A portion of the fresh feed oil continuously or intermittently bypasses the first stage and flows directly to the second stage. The first stage is fed with recycle hydrogen and the second stage with a mixture of make-up and recycle hydrogen.
Hydrotreating of pyrolysis gasoline is the subject of U.S. Pat. No. 3,492,220. The feedstock is treated in three reactors connected in series with a mixture of recycle gas and make-up hydrogen.
Hydrodenitrogenation of oil with countercurrent hydrogen is disclosed in U.S. Pat. No. 3,268,438. A mixture of recycle hydrogen and make-up hydrogen is used in each of two reaction zones.
U.S. Pat. No. 3,256,178 teaches a hydrocracking process in which limited catalytic hydrofining to remove most of the organic nitrogen impurities using a mixture of recycle gas and make-up gas is followed by a hydrocracking stage in which the liquid flows downwardly against an upflowing stream of initially ammonia-free hydrogen. A related process using a similar flow arrangement is described in U.S. Pat. No. 3,147,120.
In U.S. Pat. No. 3,132,089 there is described a hydrocracking process in which gas oil is passed, together with a mixture of recycle gas and make-up gas through a hydrofining zone, followed by low temperature hydrogenation and then by low temperature hydrocracking.
Hydrorefining of a heavy hydrocarbon oil containing asphaltenes and metallic, nitrogenous and sulphurous contaminants is taught in U.S. Pat. No. 3,180,820. According to this proposal a mixture of the oil, make-up hydrogen and recycle gas is reacted in the presence of a solid hydrogenation catalyst in a first stage to convert asphaltenes and metallic constituents and then at least the higher boiling fraction of the hydrocarbonaceous effluent is further treated in a second hydrorefining zone.
CA-A-749332 teaches hydrorefining of sulphur-containing hydrocarbon distillates in two zones in series. The feed is mixed with a mixture of recycle gas and make-up hydrogen and passed through the two zones in turn.
Other patent specifications that describe hydrodesulphurisation of hydrocarbon feedstock include FR-A-2357635 and BE-A-571792.
WO-A-89/05286 describes favourable flow conditions for effecting hydrogenation reactions, including hydrodesulphurisation.
In a conventional hydrodesulphurisation plant the hydrogen sulphide generated in any part of a catalyst bed proceeds through the entire remainder of the bed to emerge in the gas and liquid phases issuing from that bed. This is the case even in plants with multiple beds in which interbed cooling with "cold shots" of recycle gas to limit the temperature rises due to the exothermic reactions is practised. Injection of "cold shots" between beds of catalyst has the merit of reducing the H.sub.2 S partial pressure somewhat by dilution, provided that the injected gas of the "cold shot" has a low H.sub.2 S content or is H.sub.2 S-free. However, this injection procedure does have the disadvantage that the residence time of the vaporised hydrocarbons, and to some extent that of any liquid phase present, is reduced by this practice. In addition the H.sub.2 S partial pressure is highest at the exit end of the hydrotreating reactor. Since it is known that a high partial pressure of H.sub.2 S inhibits the hydrodesulphurisation and aromatic hydrogenation reactions, the catalyst activity is lowest at the exit end from the bed where the hydrogen partial pressure is also lowest and so the result is that the least reactive organic sulphur compounds, which are the sulphur compounds that will survive to the exit end of the catalyst bed, have to be treated here under the most adverse conditions prevailing in the catalyst bed. As a consequence such unreactive sulphur compounds can consequently remain unreacted and can emerge in the product oil.
The catalysts used for hydrodesulphurisation are usually also capable of effecting some hydrogenation of aromatic compounds, provided that the hydrogen sulphide level is low. The conditions required for carrying cut hydrogenation of aromatic compounds are generally similar to these required for hydrodesulphurisation although, unlike hydrodesulphurisation, aromatic hydrogenation is an equilibrium limited reaction, the equilibrium position being adversely affected by high temperatures and low hydrogen partial pressures. The inhibition of aromatics hydrogenation by hydrogen sulphide is demonstrated and discussed in the paper by Ajit V. Sapre cited above. However, as the reaction is an equilibrium that is not favoured by use of high temperatures, the conditions required for hydrodesulphurisation of cyclic and polycyclic organic sulphur compounds in a conventional plant do not favour hydrogenation of aromatic compounds. Moreover as the design of conventional hydrodesulphurisation plants results in relatively high partial pressures of H.sub.2 S, in relatively low partial pressures of hydrogen, in relatively high partial pressures of any inert gases present, and in high temperatures, at the downstream end of the plant the catalyst activity is correspondingly reduced and the conditions do not lead to significant reduction in the aromatic content of the feedstock being treated. Hence in an article entitled "Panel gives hydrotreating guides", Hydrocarbon Processing, March 1989, pages 113 to 116, it is staged at page 114:
"It is a fundamental kinetic fact that at pressures for normal middle distillate desulfurizers (500 to 800 psig) it is difficult to obtain appreciable aromatic saturation. Thus, if the feedstock is far above the 20% aromatics level, there is not much you can do with typical hydrotreaters, with any catalysts that we have knowledge of, to significantly reduce aromatics. PA1 You are then left with the unpalatable alternatives of higher pressure units, aromatic extraction, and all the other alternatives." PA1 (a) providing first-and second hydrotreatment zones each containing a charge of a sulphided hydrotreatment catalyst; PA1 (b) supplying to the first hydrotreatment zone the hydrocarbon feedstock and a hydrogen-containing gas; PA1 (c) maintaining the first hydrotreatment zone under hydrotreatment conditions effective for causing hydrodesulphurisation of organic sulphurous impurities in the hydrocarbon feedstock; PA1 (d) recovering from the first hydrotreatment zone a first intermediate product stream comprising unreacted hydrogen, hydrogen sulphide, and a mixture of hydrocarbons including a liquid first hydrocarbon fraction; PA1 (e) contacting the liquid first hydrocarbon fraction with a first stream of desulphurised recycle gas thereby to yield (A) a vaporous mixture comprising unreacted hydrogen, hydrogen sulphide, and a second hydrocarbon fraction comprising relatively more volatile components of the mixture of hydrocarbons and (B) a third liquid hydrocarbon fraction comprising relatively less volatile components of the mixture of hydrocarbons as well as residual sulphurous impurities; PA1 (f) supplying to the second hydrotreatment zone material of the third liquid hydrocarbon fraction of step (e) and a mixture of make-up hydrogen-containing gas and desulphurised recycle gas; PA1 (g) maintaining the second hydrotreatment zone under hydrotreatment conditions effective for causing hydrodesulphurisation of residual sulphurous impurities in the third liquid hydrocarbon fraction; PA1 (h) recovering from the second hydrotreatment zone a second intermediate product stream comprising unreacted hydrogen, hydrogen sulphide and a desulphurised mixture of hydrocarbons; PA1 (i) cooling material of the vaporous mixture of step (e) to effect condensation of material of the second hydrocarbon fraction; PA1 (j) subjecting unreacted hydrogen present in the vaporous mixture of step (e) to H.sub.2 S removal to form a desulphurised hydrogen-containing gas; PA1 (k) supplying desulphurised gas of step (j) as desulphurised recycle gas to steps (e) and (f); PA1 (l) separating from the second intermediate product stream of step (h) (A) a fourth desulphurised hydrocarbon fraction and (B) a gas stream containing unreacted hydrogen and hydrogen sulphide; PA1 (m) supplying material of the gas stream of step (l) as hydrogen-containing gas to step (b); and PA1 (n) recovering as a final hydrotreated product material of at least one fraction selected from the second hydrocarbon fraction and the fourth hydrocarbon fraction.
Removal of H.sub.2 S from a hydrodesulphurisation plant with a gas recycle system is normally effected by scrubbing the recycle gas with an amine. As the scrubber section has to be sufficiently large to cope with the highest levels of sulphurous impurities likely to be present in the feedstocks to be treated, the scrubber equipment has to be designed with an appropriate capacity, even though the plant will often be operated with lower sulphur feedstocks. The capital cost of such scrubber equipment is significant.
A multi-stage hydrodesulphurisation process is described in WO-A-90/13617 and WO-A-92/08772 in which the feedstock to be desulphurised is passed through a plurality of hydrodesulphurisation zones in series, each containing a charge of a hydrodesulphurisation catalyst. In each zone the feedstock flows in co-current with hydrogen. The hydrogen-containing gas feed to the first zone is gas recovered from another zone. Usually the make-up hydrogen-containing gas is supplied to the final zone. A purge gas stream is taken from the first zone and is subjected to an amine wash to recover H.sub.2 S therefrom. Provision is made for supplying H.sub.2 S, CH.sub.3 SH or the like to the first zone to ensure that the catalyst remains sufficiently sulphided.
In WO-A-90/13612 and WO-A-92/08771 there is described a hydrodesulphurisation process in which the feedstock is allowed to trickle down from tray to tray through a column reactor fitted with reaction trays, each containing a charge of a catalyst dispersed in the liquid on the tray, against an upflowing current of a hydrogen-containing gas.